Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a servicing fluid such as a fracturing fluid or a perforating fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Such a subterranean formation stimulation treatment may increase hydrocarbon production from the well.
In some wells, it may be desirable to individually and selectively create multiple fractures along a wellbore at a distance apart from each other, creating multiple “pay zones.” The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be drained/produced into the wellbore.
As part of a formation stimulation process, one or more perforations may be introduced into a casing string, a cement sheath surround a casing string, the formation, or combinations thereof, for example, for the purpose of allowing fluid communication into the formation and/or a zone thereof. For example, such perforations may be introduced via fluid jetting operation where a fluid is introduced at a pressure suitable to form perforations in the casing string, cement sheath, and/or formation. In addition, a formation stimulation process might further involve a hydraulic fracturing operation in which one or more fractures are introduced into the formation via the previously formed perforations. Such a formation stimulation procedure may create and/or extend one or more flowpaths into the wellbore from the stimulated formation and thereby increase the movement of hydrocarbons from the fractured formation into the wellbore.
Such a stimulation operation either necessitates the placement and removal of wellbore servicing tools configured for each of the perforating and fracturing operations and/or reconfiguring a suitable wellbore servicing tool between a perforating configuration and a fracturing operation. However, many conventional servicing tools require that an obturating member (e.g., a ball, dart, etc.) be pumped down to the wellbore servicing tool from the surface (e.g., run-in) and/or reversed out of the wellbore (e.g., “run-out”) in order to accomplish such reconfigurations. Either scenario results in a great deal of lost time and, thus, increased expense for the stimulation process. In addition, such conventional wellbore servicing tools are subject to wear and erosion, potentially resulting in the failure the wellbore servicing tool to transition between the perforating and fracturing configurations.
As such, there exists a need for an improved downhole wellbore servicing tool.